The subject matter of the present invention relates to a reservoir simulator including a parameter determination software which determines displacement parameters representing subsidence in an oilfield reservoir.
There are many recent reports of geomechanical modelling being used predictively for evaluation of alternative reservoir development plans. In the South Belridge field, Kern County, Calif., Hansen et al1 calibrated finite-element models of depletion-induced reservoir compaction and surface subsidence with observed measurements. The stress model was then used predictively to develop strategies to minimise additional subsidence and fissuring as well as to reduce axial compressive type casing damage. Berumen et al2 developed an overall geomechanical model of the Wilcox sands in the Arcabuz-Culebra field in the Burgos Basin, northern Mexico. This model, combined with hydraulic fracture mapping together with fracture and reservoir engineering studies, was used to optimise fracture treatment designs and improve the planning of well location and spacing.
The subject of fluid flow equations which are solved together with rock force balance equations has been discussed extensively in the literature. Kojic and Cheatham3,4 present a lucid treatment of the theory of plasticity of porous media with fluid flow. Both the elastic and plastic deformation of the porous medium containing a moving fluid is analyzed as a motion of a solid-fluid mixture. Corapcioglu and Bear5 present an early review of land subsidence modelling and then present a model of land subsidence as a result of pumping from an artesian aquifer. Demirdzic et al6,7 have advocated the use of finite volume methods for numerical solution of the stress equations both in complex domains as well as for thermo-elastic-plastic problems.
A coupling of a conventional stress-analysis code with a standard finite difference reservoir simulator is outlined by Settari and Walters8. The term xe2x80x9cpartial couplingxe2x80x9d is used because the rock stress and flow equations are solved separately for each time increment. Pressure and temperature changes as calculated in the reservoir simulator are passed to the geomechanical simulator. Updated strains and stresses are passed to the reservoir simulator which then computes porosity and permeability. Issues such as sand production, subsidence, compaction that influence rock mass conservation are handled in the stress-analysis code. This method will solve the problem as rigorously as a fully coupled (simultaneous) solution if iterated to full convergence. An explicit coupling, i.e. a single iteration of the stress model, is advocated for computational efficiency.
The use of a finite element stress simulator with a coupled fluid flow option is discussed by Heffer et al9 and by Gutierrez and Lewis10.
Standard commercial reservoir simulators use a single scalar parameter, the pore compressibility, as discussed by Geertsma11 to account for the pressure changes due to volumetric changes in the rock. These codes generally allow permeability to be modified as a function of pore pressure through a table. This approach will not be adequate when the flow parameters exhibit a significant variation with rock stress. Holt12 found that for a weak sandstone, permeability reduction was more pronounced under non-hydrostatic applied stress, compared with the slight decrease measured under hydrostatic loading. Rhett and Teufel13 have shown a rapid decline in matrix permeability with increase in effective stress. Ferfera et al14 worked with a 20% porosity sandstone and found permeability reductions as high as 60% depending on the relative influence of the mean effective stress and the differential stress. Teufel et al15 and Teufel and Rhett16 found, contrary to the assumption that permeability will decrease with reservoir compaction and porosity reduction, that shear failure had a beneficial influence on production through an increase in the fracture density.
Oil recovery operations are seeing increased use of integrated geomechanical and reservoir engineering to help manage fields. This trend is partly a result of newer, more sophisticated measurements that are demonstrating that variations in reservoir deliverability are related to interactions between changing fluid pressures, rock stresses and flow parameters such as permeability. Several recent studies, for example, have used finite-element models of the rock stress to complement the standard reservoir simulation.
This specification discusses current work pertaining to: fully and partially coupling geomechanical elastic/plastic rock stress equations to a commercial reservoir simulator. This finite difference simulator has black-oil, compositional and thermal modes and all of these are available with the geomechanics option. In this specification, the implementation of the aforementioned stress equations into the code, hereinafter called the xe2x80x98Parameter Determination Softwarexe2x80x99, is discussed. Some work on benchmarking against an industry standard stress code is also shown as well as an example of the coupled stress/fluid flow. The goal in developing this technology within the simulator is to provide a stable, comprehensive geomechanical option that is practical for large-scale reservoir simulation.
Further scope of applicability of the present invention will become apparent from the detailed description presented hereinafter. It should be understood, however, that the detailed description and the specific examples, while representing a preferred embodiment of the present invention, are given by way of illustration only, since various changes and modifications within the spirit and scope of the invention will become obvious to one skilled in the art from a reading of the following detailed description.